Methods and systems for estimating sizes and effects of wellbore obstructions in water injection wells

ABSTRACT

Methods and systems to estimate physical dimensions of actual obstructions identified as being in a wellbore of an injection well are provided. Methods and systems include the determination of a well performance model with a simulated obstruction, using inflow performance and outflow performance relationships.

FIELD OF INVENTION

The present invention relates generally to the oil industry,particularly reservoir engineering, and more particularly to systems,program product, and methods for detecting the presence of obstructionsin the wellbores of injection wells and for evaluating the dimensions ofthe obstructions and their effects on the performance of the injectionwells.

BACKGROUND

Efficient and productive recovery of oil and natural gas fromunderground deposits involves several complex technologies. For example,primary recovery relies on underground pressure, which can originatefrom several sources including an underlying water layer below the oillayer or a gas cap formed of gas collected immediately above the oillayer. Whether or not such underground pressure initially existed, oncereservoir pressure has either been depleted or is otherwise below aminimum value, oil must be brought to the surface using secondarymethodologies. One such secondary methodology includes injecting waterbelow the oil layer. Another methodology includes injecting a gas abovethe oil layer. Other methodologies of extracting oil, particularly whenunderground pressure has been depleted to a point where the reservoircannot be sufficiently pressurized, include reducing the viscositythrough the injection of heat, vapor, surfactants, solvents, or misciblegases (e.g., carbon dioxide).

Water is a particularly useful tool because it can be used to pressurizea virgin or depleted reservoir (both naturally and through injection),but can also be used to proactively maintain reservoir pressure and/orto direct oil in a reservoir toward an existing oil well. Whileproduction wells can be converted into injection wells, water-injectionwells are also drilled specifically for the purpose of enhanced oilrecovery. Water is then pumped into the reservoir, or gravity can helpto push the liquid into the formation. Performance of water injectionwells is monitored to ensure desired operation of the oil recoveryprocess. When an obstruction forms in the wellbore, effective detectionand estimation techniques are needed to characterize and remove suchobstruction. Obstructions usually result from deposits in the wellbore,for example, scale paraffin, asphlatenes, salt, solids or corrosionproducts. Obstructions can also result from debris or particles in theinjected fluid. Obstructions can also result from build-up of fines andscale in the wellbore. Obstructions can also result from mechanicaldownhole fish issues such as those resulting from items left in awellbore, including, but not limited to, pieces of various drilling,logging, or production equipment. Deformations in the tubing or casingof the wellbore can also cause obstructions. These obstructions can beremoved or reduced by one or more of chemical and mechanicaltechnologies, depending on several factors including location of theobstruction and its properties. A chemical technology often used intreating obstructions involves acid treatments. Various acids, such assulfuric acid and hydrochloric acid, have been injected into thewellbore in order to remove blocking material and to increase theproductivity of injection wells. Obstructions can also be removed ordecreased in size by mechanical milling using coiled tubing or wirelineor other specialized apparatuses.

SUMMARY OF THE INVENTION

The Applicants recognize the importance of detecting a presence of atleast one obstruction in a wellbore of an injection well and determiningdimensions of that obstruction. Various embodiments of methods andapparatus for detecting a presence of at least one obstruction in awellbore of an injection well and determining dimensions of thatobstruction are provided herein. Exemplary embodiments of the inventioninclude a method of detecting a presence of at least one obstruction ina wellbore of an injection well and determining dimensions of thatobstruction. An embodiment of the invention includes a method toestimate one or more physical dimensions of one or more actualobstructions identified as being in a wellbore of an injection well.This method includes the steps of: (a) estimating one or more locationswithin the wellbore and one or more physical dimensions of one or moreactual obstructions to thereby define a simulated obstruction within thewellbore; (b) obtaining two or more sets of actual measurements of twoor more characteristics of fluid flow in the wellbore, including two ormore actual injection rates and two or more actual injection pressures;(c) calculating a plurality of actual upstream pressure values of thesimulated obstruction, the upstream pressure values being responsive toa first outflow performance relationship and a first set of actualmeasurements of two or more characteristics of fluid flow in thewellbore, the first set of measurements including a first set of actualfluid injection rates and a first set of actual injection pressures; (d)calculating a plurality of corresponding downstream pressure valuesacross the simulated obstruction, the corresponding downstream pressurevalues being responsive to a first estimated injectivity index value,one or more actual measurements of one or more characteristics of thereservoir associated with the injection well, and the first set ofactual measurements of two or more characteristics of fluid flow in thewellbore; (e) determining one or more functions to associate a pluralityof pressure differentials between the upstream pressure values and thecorresponding downstream pressure values with the first set of actualfluid injection rates responsive to a function of estimated downholechoke behavior for the wellbore to thereby model the fluid flow acrossthe simulated obstruction to thereby define the simulated obstructionmodel; (f) determining a second outflow performance relationship for thefluid flow through the wellbore responsive to the simulated obstructionmodel to thereby model well performance with the simulated obstruction;(g) determining a second estimated injectivity index value responsive tomatching a second set of actual measurements of two or morecharacteristics of fluid flow in the wellbore with a set of simulatedfluid flow values obtained from the well performance model with thesimulated obstruction, the second set of actual measurements including asecond set of actual fluid injection rates and a second set of actualinjection pressures; (h) performing iteratively steps (b) to (g) untilthe first estimated injectivity index value and the second estimatedinjectivity index value converge within preselected tolerance limits;and (i) determining one or more physical dimensions of one or moreactual obstructions in the wellbore responsive to the simulatedobstruction model and a plurality of measurements of one or morecharacteristics associated with the wellbore when the first estimatedinjectivity index value and the second estimated injectivity index valueconverge within preselected tolerance limits.

Exemplary embodiments of the invention include a system to estimate oneor more physical dimensions of one or more actual obstructionsidentified as being in a wellbore of an injection well. The systemincludes one or more processors, one or more input and output units incommunication with the one or more processors and positioned to receivea user selection of a wellbore of an injection well; and one or moredatabases in communication with the one or more processors. The one ormore databases include a plurality of actual measurements of one or morecharacteristics of fluid flow in the wellbore of an injection well, aplurality of actual measurements of one or more characteristics of areservoir associated to the injection well, and a plurality of actualmeasurements of one or more characteristics of the wellbore of theinjection well. The system also includes a non-transitorycomputer-readable medium positioned in communication with the one ormore processors and having computer program stored thereon. The computerprogram includes a set of instructions that when executed by one or moreprocessors cause the one or more processors to perform operations of:(a) estimating one or more locations within the wellbore and one or morephysical dimensions of one or more actual obstructions to thereby definea simulated obstruction within the wellbore; (b) obtaining two or moresets of actual measurements of two or more characteristics of fluid flowin the wellbore including two or more actual injection rates and two ormore actual injection pressures; (c) calculating a plurality of actualupstream pressure values of the simulated obstruction, the upstreampressure values being responsive to a first outflow performancerelationship and a first set of actual measurements of two or morecharacteristics of fluid flow in the wellbore, the first set ofmeasurements including a first set of actual fluid injection rates and afirst set of actual injection pressures; (d) calculating a plurality ofcorresponding downstream pressure values across the simulatedobstruction, the corresponding downstream pressure values beingresponsive to a first estimated injectivity index value, one or moreactual measurements of one or more characteristics of the reservoirassociated with the injection well, and the first set of actualmeasurements of two or more characteristics of fluid flow in thewellbore; (e) determining one or more functions to associate a pluralityof pressure differentials between the upstream pressure values and thecorresponding downstream pressure values with the first set of actualfluid injection rates responsive to a function of estimated downholechoke behavior for the wellbore to thereby model the fluid flow acrossthe simulated obstruction to thereby define the simulated obstructionmodel; (f) determining a second outflow performance relationship for thefluid flow through the wellbore responsive to the simulated obstructionmodel to thereby model well performance with the simulated obstruction;(g) determining a second estimated injectivity index value responsive tomatching a second set of actual measurements of two or morecharacteristics of fluid flow in the wellbore with a set of simulatedfluid flow values obtained from the well performance model with thesimulated obstruction, the second set of actual measurements including asecond set of actual fluid injection rates and a second set of actualinjection pressures; (h) performing iteratively steps (b) to (g) untilthe first estimated injectivity index value and the second estimatedinjectivity index value converge within preselected tolerance limits;and (i) determining one or more physical dimensions of one or moreactual obstructions in the wellbore responsive to the simulatedobstruction model and a plurality of measurements of one or morecharacteristics associated with the wellbore when the first estimatedinjectivity index value and the second estimated injectivity index valueconverge within preselected tolerance limits.

Exemplary embodiments of the invention include a computer-implementedmethod to determine dimensions of one or more actual obstructionsidentified as being in a wellbore of an injection well. The methodincludes (a) obtaining a plurality of measurements of one or morecharacteristics of fluid flow in a wellbore of an injection well, aplurality of measurements of one or more characteristics of a reservoirassociated with the injection well, and a plurality of measurements ofone or more characteristics associated with the wellbore of theinjection well; (b) creating one or more correlations based on a firstestimated injectivity index to simulate fluid flow across one or moresimulated mechanical obstructions to thereby define a simulatedobstruction performance model, the one or more correlations beingresponsive to the plurality of measurements of one or morecharacteristics of fluid flow in the wellbore of the injection well, theplurality of measurements of one or more characteristics of thereservoir associated with the injection well, the plurality ofmeasurements of one or more characteristics associated with the wellboreof the injection well, and a plurality of simulated fluid flowmeasurements across the at least one simulated mechanical obstruction inthe wellbore; (c) determining a second estimated injectivity index,responsive to the simulated obstruction performance model, the pluralityof measurements of one or more characteristics of actual fluid flow inthe wellbore of the injection well, the plurality of measurements of oneor more characteristics of the reservoir associated with the injectionwell, and the plurality of measurements of one or more characteristicsassociated with the wellbore of the injection well; (d) performingiteratively steps (a) to (c) until the first estimated injectivity indexvalue and the second estimated injectivity index value converge withinpreselected tolerance limits; and (e) determining dimensions of the oneor more actual obstruction in the wellbore responsive to the simulatedobstruction performance model and the plurality of measurements of oneor more characteristics associated with the wellbore of the injectionwell when the first estimated injectivity index and the second estimatedinjectivity index converge within acceptable tolerance limits.

In certain embodiments of the invention, the simulated obstructionperformance model includes at least one of the following: an outflowperformance relationship analysis and an inflow performance relationshipanalysis. The outflow performance relationship analysis is responsive tothe plurality of measurements of one or more characteristics of fluidflow in the wellbore of the injection well. The inflow performancerelationship analysis is responsive to the plurality of measurements ofone or more characteristics of fluid flow in the wellbore of theinjection well and the plurality of measurements of one or morecharacteristics of the reservoir associated with the injection well.

BRIEF DESCRIPTION OF THE DRAWINGS

The application file contains at least one drawing executed in color.Copies of this patent application publication with color drawings willbe provided by the Patent and Trademark Office upon request and paymentof the necessary fee.

So that the manner in which the above-recited features, aspects andadvantages of the invention, as well as others that will becomeapparent, are attained and can be understood in detail, more particulardescription of the invention briefly summarized above can be had byreference to the embodiments thereof that are illustrated in thedrawings that form a part of this specification. It is to be noted,however, that the appended drawings illustrate some embodiments of theinvention and are, therefore, not to be considered limiting of theinvention's scope, for the invention can admit to other equallyeffective embodiments.

FIG. 1 is a schematic block diagram of an exemplary method to estimateone or more physical dimensions of one or more actual obstructions in awellbore of an injection well.

FIG. 2 is an illustration of a simulated obstruction in a wellbore of aninjection well.

FIG. 3 is a schematic block diagram of an exemplary method to estimateone or more physical dimensions of one or more actual obstructions in awellbore of an injection well.

FIGS. 4 a, 4 b, and 4 c are graphical representations of the fluidinjection rate and injection pressure history of an exemplary Well Aduring different time periods.

FIGS. 5 a and 5 b are graphical representations of the actualmeasurements of fluid flow rates from Well A during different timeperiods and data points from both the Joshi model and the injectioninjectivity model.

FIG. 6 is a graphical representation of the fluid flow rate and thepressure differential variables from the simulated obstruction model.

DETAILED DESCRIPTION

The present inventions will be described more fully hereinafter withreference to the accompanying drawings in which embodiments of theinvention are shown. These inventions may, however, be embodied in manydifferent forms and should not be construed as limited to the exemplaryembodiments set forth herein; rather, these embodiments are provided sothat this disclosure will be thorough and complete, and will fullyconvey the scope of the inventions to those skilled in the art.

While these embodiments have been described with emphasis on theembodiments, it should be understood that within the scope of theappended claims, the embodiments might be practiced other than asspecifically described herein. Although the invention has been shown inonly a few of its forms, it should be apparent to those skilled in theart that it is not so limited but susceptible to various changes withoutdeparting from the scope of the invention. Accordingly, it is intendedto embrace all such alternatives, modifications, and variations as fallwithin the spirit and broad scope of the appended claims.

It is to be fully recognized that the different teachings of the variousembodiments discussed below may be employed separately or in anysuitable combination to produce desired results. The variouscharacteristics mentioned above, as well as other features andcharacteristics described in more detail below, will be readily apparentto those skilled in the art upon reading the following detaileddescription of the various embodiments, and by referring to theaccompanying drawings. In the drawings and specification, there havebeen disclosed embodiments of the invention and, although specific termsare employed, they are used in a generic and descriptive sense only andnot for the purpose of limitation, the scope of the invention being setforth in the following claims. For example, those skilled in the art mayrecognize that certain steps can be combined into a single step.Furthermore, language referring to order, such as first and second,should be understood in an exemplary sense and not in a limiting sense.In the drawings and description, like parts are marked throughout thespecification and drawings with the same reference numerals,respectively. The prime notation, if used, indicates similar elements inalternative embodiments. The drawings are not necessarily to scale.Certain features of the disclosure may be shown exaggerated in scale orin somewhat schematic form and some details of conventional elements maynot be shown in the interest of clarity and conciseness.

As used herein, the terms “comprising,” “containing,” “including,” and“such as” are used in their open, non-limiting sense.

A fluid as used herein refers to any liquid or gas moving through awellbore of an injection well. Embodiments of the present invention canbe used in wellbores that utilize water, brine, other aqueous solution,organic solutions, organic mixtures, steam, carbon dioxide, or otherappropriate fluids.

An obstruction as used herein refers to any restriction in the flow pathof the fluid through a wellbore of an injection well. An obstruction canbe in the openhole section of the wellbore. Obstructions can form in thetubing or casing in tubing-less completions. One common way forobstructions to occur in wellbores of injection wells is by thedeposition of particulate material or by particles transported from aloose structure. Obstructions also result from scale deposits that formdue to incompatibilities between the injection and formation water.Obstructions can also result from mechanical downhole fish issues suchas those resulting from items left in a wellbore, including, but notlimited to, pieces of various drilling, logging or production equipment.For example, downhole mechanical fish issues arise when wireline orcoiled tubing bottom hole assemblies are lost in the wellbore during awell intervention operation. Deformations in the tubing or casing of thewellbore can also cause obstructions. For example, tubing collapsecaused by tensile and collapse loads can result in obstructions in thewellbore.

Obstructions cause changes in the one or more characteristics of fluidflow in a wellbore of an injection well. For example, obstructions cancause increased injection pressure of injection wells. Obstructions canalso cause decreased injection volume of fluid through the wellbore ofinjection wells. The presence of a downhole obstruction can result inadditional pressure drop, further increasing the injection pressure witha drop in the injection rate.

The concept of skin is used to characterize the changes in the pressurebehavior associated with the injection wells. Skin is the pressure dropdue to non-ideal conditions. These pressure changes can be caused bychanges in the wellbore or in the reservoir or in both. For example,certain skin is attributed to damage or stimulation associated with theinjection wells. Positive skin, where the pressure is higher than itshould be, usually represents damage; while negative skin, where thepressure is lower than it should be, usually represents stimulation.Mechanical skin is the reduction in permeability in the near-wellborearea resulting from mechanical factors. Such mechanical factors include,for example, without limitation, the displacement of debris that plugsthe perforations or formation matrix. Formation damage skin refers tothe decrease in permeability that can occur in the near wellbore regionof a reservoir. This usually represents a positive skin effect. Theformation near the wellbore can also be damaged by physical crushing orcompaction of the rock. Laminar skin for horizontal wells is expressedas the sum of perforation geometry skin, formation damage skin andcrushed zone skin surrounding the perforation. Achieving effective acidstimulation requires the distribution of treatment fluids along theentire reservoir length. Several previous studies have demonstrated theeffect and significance of the mechanical skin as compared to theformation damage skin. Removal of obstruction is as important asimproving the formation damage skin to recover water injection rate.

Exemplary embodiments of the invention include a method of detecting apresence of at least one obstruction in a wellbore of an injection welland determining dimensions of that obstruction. The method includesmeasuring characteristics of fluid flow in a wellbore of an injectionwell, characteristics of a reservoir associated to the injection well,and characteristics of the wellbore of the injection well. Actual andsimulated measurements of characteristics of fluid flow in a wellbore ofan injection well, characteristics of a reservoir associated to theinjection well, and characteristics of the wellbore of the injectionwell, can be stored on computer readable medium, can be part of adatabase, which may optionally be accessible via a communicationsnetwork. According to various exemplary embodiments of the presentinvention, such a database can be any database structure as is known andunderstood by those skilled in the art. The databases discussed hereincan be, for example, any sort of organized collection of data in digitalform. Databases can include the database structure as well as thecomputer programs that provide database services to other computerprograms or computers, as defined by the client-server model, and anycomputer dedicated to running such computer programs (i.e., a databaseserver). An exemplary database model, for example, is Microsoft SQLServer 2008 R2. Databases can include a database management system(DBMS) consisting of software that operates the database, providesstorage, access, security, backup and other facilities. Databases canimplement any known database model or database models, including, forexample, a relational model, a hierarchical model, a network model, oran object-oriented model. It will be appreciated by those having skillin the art that data described herein as being stored in the databasescan also be stored or maintained in non-transitory memory and accessedamong subroutines, functions, modules, objects, program products, orprocesses for example, according to objects and/or variables of suchsubroutines, functions, modules, objects, program products or processes.Any of the fields of the records, tables, libraries, and so on of thedatabase can be multi-dimensional structures resembling an array ormatrix and can include values or references to other fields, records,tables, or libraries. Any of the foregoing fields can contain eitheractual values or a link, a join, a reference, or a pointer to otherlocal or remote sources for such values.

The characteristics of fluid flow in a wellbore used in analyzing wellperformance include one or more of the following: surface injectionpressure, bottomhole injection pressure, fluid velocity, fluid flowrate, fluid temperature, fluid density, fluid viscosity, frictionfactors, and combinations thereof. These characteristics of fluid flowin a wellbore can be measured by a variety of measurement devices,including, but not limited to, flow sensors, pressure gauges, andtemperature sensors. Measurements can be transmitted to the surface orrecorded in downhole memory devices.

The characteristics of a reservoir associated to the injection well usedin analyzing well performance include one or more of the following:reservoir pressure, resistivity, permeability, porosity, formationthickness, rock properties, reservoir structure, reservoir geometry,formation skin damage, and combinations thereof. These characteristicsof a reservoir are measured by a variety of measurement devices,including, but not limited to, flow sensors, pressure gauges,temperature sensors, and devices that measure the electric, acoustic,radioactive and electromagnetic properties of the reservoir. A varietyof logging techniques can be used. Measurements can be transmitted tothe surface or recorded in downhole memory devices.

The characteristics of the wellbore of the injection well used inanalyzing well performance include one or more of the following:wellbore radius, wellbore length, wellbore structure, mechanicalproperties, wellbore geometry, and combinations thereof. For example,certain well performance models use inner diameters and lengths of thetubing or casing sections of the wellbore. These characteristics of thewellbore are measured by a variety of measurement devices, including,but not limited to, flow sensors, pressure gauges, and temperaturesensors. Measurements can be transmitted to the surface or recorded indownhole memory devices.

A flow sensor as used herein is a device for sensing the rate of flow,and can be a part of flowmeters and flow loggers. A flowmeter is adevice for measuring the rate of flow of fluid, and for example, withoutlimitations, include solar flowmeters, ultrasonic flowmeters, andmagnetic flowmeters. Flow measuring devices can be affixed at specificlocations in the wellbore or can be lowered and raised in the wellborecontaining one or more flowing fluids whose velocity or flow rate are tobe determined.

In certain embodiments, the method of detecting a presence of anobstruction in a wellbore of a fluid injection well and determiningdimensions of that obstruction includes creating one or more wellperformance models—(1) a well performance model based on actualmeasurements of one or more characteristics of fluid flow in a wellboreof an injection well, actual measurements of one or more characteristicsof a reservoir associated to the injection well, and actual measurementsof one or more characteristics of the wellbore of the injection well,and (2) a simulated obstruction performance model based on both theactual measurements of one or more characteristics of fluid flow in awellbore of an injection well, measurements of one or morecharacteristics of a reservoir associated to the injection well, andmeasurements of one or more characteristics of the wellbore of theinjection well, and the simulated fluid flow computations across asimulated mechanical obstruction in the wellbore. Another wellperformance model that can be used includes a well performance modelbased on ideal or substantially ideal measurements of one or morecharacteristics of fluid flow in a wellbore of an injection well, idealor substantially ideal measurements of one or more characteristics of areservoir associated to the injection well, and ideal or substantiallyideal measurements of one or more characteristics of the wellbore of theinjection well.

Well performance modeling of single phase flow water injection wells, isdeemed reliable and predictive due to the unique match it demonstratescompared to the actual injection history. For water injection wells,where no gas is present and incompressible flow is assumed, theuncertainty in frictional and turbulent flow pressure losses is usuallyminimal. Calculation of the bottomhole injection pressure based on thesurface pressure and the fluid flow rate is usually very accurate anddependent on the quality of the data measured on the surface flowmeters.Solar flowmeters, for example, are utilized to record the flow rate andsurface injection pressure continuously to monitor the well injectionperformance. Solar flowmeters operate on recording the pressure dropacross an orifice plate installed in the flow line upstream of thewellhead. The water flow rate is then calculated using similar fluidmechanics equations as used to estimate differential pressure acrosssurface chokes. Both the outflow and the inflow performancerelationships are determined using this available real-time data andconverting surface injection pressure to the respective downholepressure. Then the pressure is plotted against the flow rate to get anupdated well performance models. By means of such models, injectivityindex, reservoir pressure and even total skin can be easily estimated.In certain embodiments, one reliable fall-off test is sufficient tocalibrate the well performance model and estimate permeability andthickness inputs in horizontal inflow performance correlations. Aninjector fall-off test involves the measurement and analysis of pressuredata taken after an injection well is shut in. Wellhead pressure risesduring injection, and if the well remains full of liquid after shut-inof an injector, the pressure can be measured at the surface, andbottomhole pressures can be calculated by adding the pressure from thehydrostatic column to the wellhead pressure. In one embodiment, solarflowmeter data (SFM) was analyzed along with well test results toevaluate the well performance before and after acid stimulation to takeaccount the contributions of both mechanical skin and damage skinimprovement.

Certain embodiments of the invention are used for the evaluation andquantification of wellbore obstructions effect on the well performanceof water injection wells. In certain embodiments of the invention, dataregarding the well performance is analyzed to develop cost-effectivewell performance diagnoses prior to taking any costly actions to remedythe well conditions such as major acid stimulation treatments. Certainexemplary methods of the invention are used to estimate downholeobstructions restriction sizes such as scale using the surface injectiondata.

Exemplary embodiments of the invention include a computer-implementedmethod to determine dimensions of one or more actual obstructionsidentified as being in a wellbore of an injection well. The methodincludes (a) obtaining a plurality of measurements of one or morecharacteristics of fluid flow in a wellbore of an injection well, aplurality of measurements of one or more characteristics of a reservoirassociated with the injection well, and a plurality of measurements ofone or more characteristics associated with the wellbore of theinjection well; (b) creating one or more correlations based on a firstestimated injectivity index to simulate fluid flow across one or moresimulated mechanical obstructions to thereby define a simulatedobstruction performance model, the one or more correlations beingresponsive to the plurality of measurements of one or morecharacteristics of fluid flow in the wellbore of the injection well, theplurality of measurements of one or more characteristics of thereservoir associated with the injection well, the plurality ofmeasurements of one or more characteristics associated with the wellboreof the injection well, and a plurality of simulated fluid flowmeasurements across the at least one simulated mechanical obstruction inthe wellbore; (c) determining a second estimated injectivity index,responsive to the simulated obstruction performance model, the pluralityof measurements of one or more characteristics of actual fluid flow inthe wellbore of the injection well, the plurality of measurements of oneor more characteristics of the reservoir associated with the injectionwell, and the plurality of measurements of one or more characteristicsassociated with the wellbore of the injection well; (d) performingiteratively steps (a) to (c) until the first estimated injectivity indexvalue and the second estimated injectivity index value converge withinpreselected tolerance limits; and (e) determining dimensions of the oneor more actual obstruction in the wellbore responsive to the simulatedobstruction performance model and the plurality of measurements of oneor more characteristics associated with the wellbore of the injectionwell when the first estimated injectivity index and the second estimatedinjectivity index converge within acceptable tolerance limits.

In certain embodiments of the invention, the simulated obstructionperformance model includes at least one of the following: an outflowperformance relationship analysis and an inflow performance relationshipanalysis. The outflow performance relationship analysis is responsive tothe plurality of measurements of one or more characteristics of fluidflow in the wellbore of the injection well. The inflow performancerelationship analysis is responsive to the plurality of measurements ofone or more characteristics of fluid flow in the wellbore of theinjection well and the plurality of measurements of one or morecharacteristics of the reservoir associated with the injection well.

In certain embodiments, the well performance model is based on an inflowperformance relationship (IPR) and outflow performance relationship(OPR) analysis to estimate downhole obstruction size in power waterinjectors. Solar flowmeter data recorded at the surface was used tovalidate and calibrate out-flow and in-flow performance models takingadvantage of the single-phase flow behavior. The OPR analysis wasconstructed by considering gravitational and frictional pressure changesto convert the injection pressure to bottomhole flowing pressure.

The IPR for a well is the relationship between the fluid injection rateand the pressure differential between the bottomhole injection pressureand the reservoir pressure. In certain embodiments of this invention,two inflow models were built and calibrated—a constant injectivity indexmodel and a Joshi model—to take in account the other reservoirattributes such as permeability, anisotropy and skin factor. The IPRmodels were constructed based on the valid assumption that the reservoirperformance in water injection wells is exactly the same as oilreservoirs that are above the bubble point. Some of the factorsaffecting IPR include pressure inside the reservoir, nature of reservoirfluids, and types of rocks. A straight line IPR is expected if oneassumes an equivalent injectivity index across the horizontal section.The Joshi correlation and constant injectivity index models were used topredict the horizontal inflow performance relationship and to accountfor skin, formation thickness and anisotropy effects. Rock propertiesdata such reservoir permeability (K) and reservoir thickness (h) wereestimated from well test and offset wells core analysis, and thencalibrated later using the solar flowmeter data. Reservoir pressurevalues were collected from the pressure surveys performed on the well.

Below is the constant injectivity index equation for water injectionwells;

q=II×(P _(wf) −P _(R))

Where,

-   -   q=injection rate, bbl/day    -   II=Injectivity Index, bbl/day/psi    -   P_(wf)=bottomehole injection pressure, psi    -   P_(R)=Reservoir pressure, psi

Outflow Performance Relationship (OPR) includes measurements of fluidflow and the pressure difference across each segment of the fluid flow.Calculating the pressure drop at each segment is serious problem as itinvolves the simultaneous flow of oil, gas and water (multiphase flow),and the pressure drop is dependent on many interrelatedvariables.Outflow performance curves are constructed for a specific wellby calculating the P_(wf) at different injection rates and surfacepressure values. Pressure changes due to gravity, friction, casing sizechange and turbulence were included in the model. Each casing string hasits own turbulence and frictional losses. The incompressible fluidproperties of water are assumed to be independent of pressure andtemperature changes. In an exemplary model, pipe roughness to diameterratio is assumed to be 0.0006.

Below, is the flow equation addressing the pressure gradient in thetubulars:

$\frac{P}{L} = {\frac{\rho_{w}\sin \; \varphi}{144} + \frac{f\; \rho_{w}v_{m}^{2}}{24\mspace{11mu} g_{c}d}}$

Where,

${\frac{P}{L} = {{pressure}\mspace{14mu} {drop}\mspace{14mu} {gradient}}},$

psi/ft

-   -   g_(c)=gravity component, 32.2 ft/s²    -   ρ_(w)=Water density, Ibm/ft³    -   ν_(m)=fluid velocity, ft/s    -   f=friction factor, unitles    -   d=Pipe inside diameter, inch    -   Ø=Wellbore deviation angle.        The IPR and OPR models were coupled to determine the expected        flow conditions of the well at different injection pressure        values.

FIG. 1 is an illustration of an exemplary embodiment of the methods ofthe invention. In one embodiment, the method includes estimating one ormore physical dimensions of one or more actual obstructions identifiedas being in a wellbore of an injection well. The method includesestimating 101 one or more locations within the wellbore and one or morephysical dimensions of one or more actual obstructions to thereby definea simulated obstruction within the wellbore. Locations can be determinedby well intervention. A wireline tool can be lowered in the wellbore tofind the obstruction depth. The method further includes obtaining 102two or more sets of actual measurements of two or more characteristicsof fluid flow in the wellbore including two or more actual injectionrates and two or more actual injection pressures. In certainembodiments, those data sets are obtained when there is a confirmedobstruction. The method further includes calculating 103 a plurality ofactual upstream pressure values of the simulated obstruction, theupstream pressure values being responsive to a first outflow performancerelationship and a first set of actual measurements of two or morecharacteristics of fluid flow in the wellbore, the first set ofmeasurements including a first set of actual fluid injection rates and afirst set of actual injection pressures. The method further includescalculating 104 a plurality of corresponding downstream pressure valuesacross the simulated obstruction, the corresponding downstream pressurevalues being responsive to a first estimated injectivity index value,one or more actual measurements of one or more characteristics of thereservoir associated with the injection well, and the first set ofactual measurements of two or more characteristics of fluid flow in thewellbore. In certain embodiments, the first estimated injectivity indexvalues are based on previously measured injectivity index values. Themethod further includes determining one or more functions to associate aplurality of pressure differentials between the upstream pressure valuesand the corresponding downstream pressure values 105 with the first setof actual fluid injection rates responsive to a function of estimateddownhole choke behavior for the wellbore to thereby model the fluid flowacross the simulated obstruction to thereby define the simulatedobstruction model 106. The method further includes determining 107 asecond outflow performance relationship for the fluid flow through thewellbore responsive to the simulated obstruction model to thereby modelwell performance with the simulated obstruction and determining 108 asecond estimated injectivity index value responsive to matching a secondset of actual measurements of two or more characteristics of fluid flowin the wellbore with a set of simulated fluid flow values obtained fromthe well performance model with the simulated obstruction, the secondset of actual measurements including a second set of actual fluidinjection rates and a second set of actual injection pressures. Theabove described steps are performed 109 iteratively until the firstestimated injectivity index value and the second estimated injectivityindex value converge within preselected tolerance limits. The methodfurther includes determining 110 one or more physical dimensions of oneor more actual obstructions in the wellbore responsive to the simulatedobstruction model and a plurality of measurements of one or morecharacteristics associated with the wellbore when the first estimatedinjectivity index value and the second estimated injectivity index valueconverge within preselected tolerance limits.

In certain embodiments, the preselected tolerance limit is approximatelyabout 5%. The preselected tolerance limit can be expressed as ±5%. Incertain embodiments, the preselected tolerance limit is ±6%. In certainembodiments, the preselected tolerance limit is ±4%.

Any obstruction in wellbore is, conventionally, considered part of theOPR, so there is the need to have a reliable model relating the pressuredrop across any wellbore restriction to the flow rate. The injectivityindex seen by any rate test or well test of a well having an obstructionin the wellbore is a total injectivity index affected by both theformation damage, if any, and the presence of a flow restriction thatconsumes the flow energy of the fluids before they reach the reservoirrock.

Furthermore, the methods to estimate one or more physical dimensions ofone or more actual obstructions identified as being in a wellbore of aninjection well according to exemplary embodiments of the presentinvention, and as discussed above, can be implemented using one or morecomputers, one or more servers, one or more databases, and one or morecommunications networks. The methods of estimating one or more physicaldimensions of one or more actual obstructions identified as being in awellbore of an injection well as discussed above can be driven by acomputer that can include, according to various exemplary embodiments ofthe present invention, at least a memory, a processor, and aninput/output device. As used herein, the processor can include, forexample, one or more microprocessors, microcontrollers, and other analogor digital circuit components configured to perform the functionsdescribed herein. The processor is the “brains” of the respectivecomputer, and as such, can execute computer program product or products.For example, the processor in simulated modeling system can execute acomputer program product or instructions stored in memory of thecomputer, including, for example, a product to facilitate the generationof well performance models. Such a product can include a set ofinstructions to display a user interface at a remote computer that wouldallow a user to access and input, if required, actual measurements ofone or more characteristics of fluid flow in a wellbore of an injectionwell, measurements of one or more characteristics of a reservoirassociated to the injection well, and measurements of one or morecharacteristics of the wellbore of the injection well. Such a productcan also include instructions to carry out exemplary embodiments of themethods described above. The processor can be any commercially availableterminal processor, or plurality of terminal processors, adapted for usein or with the computer. The processor can be, for example, the Intel®Xeon® multicore terminal processors, Intel® micro-architecture Nehalem,and AMD Opteron™ multicore terminal processors, Intel® Core® multicoreprocessors, Intel® Core iSeries® multicore processors, and otherprocessors with single or multiple cores as is known and understood bythose skilled in the art. The processor can be operated by operatingsystem software installed on memory, such as Windows Vista, Windows NT,Windows XP, UNIX or UNIX-like family of systems, including BSD andGNU/Linux, and Mac OS X. The processor can also be, for example the TIOMAP 3430, Arm Cortex A8, Samsung S5PC100, or Apple A4. The operatingsystem for the processor can further be, for example, the Symbian OS,Apple iOS, Blackberry OS, Android, Microsoft Windows CE, Microsoft Phone7, or PalmOS.

A computer can further include a non-transitory memory or more than onenon-transitory memories (referred to as memory herein). Memory can beconfigured, for example, to store data, including computer programproduct or products, which include instructions for execution on theprocessor. Memory can include, for example, both non-volatile memory,e.g., hard disks, flash memory, optical disks, and the like, andvolatile memory, e.g., SRAM, DRAM, and SDRAM as required to supportembodiments of the instant invention. As one skilled in the art willappreciate, though the memory is depicted on, e.g., a motherboard, ofthe computer, the memory can also be a separate component or device,e.g., flash memory, connected to the computer through an input/outputunit or a transceiver. As one skilled in the art will understand, theprogram product or products, along with one or more databases, datalibraries, data tables, data fields, or other data records can be storedeither in memory or in separate memory (also non-transitory), forexample, associated with a storage medium such as a database (notpictured) locally accessible to the computer, positioned incommunication with the computer through the I/O device.

As illustrated by an example in FIG. 2, a simulated obstruction ismodeled to be a downhole choke set at a certain opening of the wellbore,where the diameter is D₁, and causes a pressure drop that reduces thebottomhole injection pressure P_(wf). The diameter of the simulatedreservoir pressure P_(R). This is done for a sample set of injectiondata to reduce uncertainty. Diameter of the simulated obstruction, or anequivalent choke, is D₂. The upstream pressure value of the obstruction(p₂) is calculated using OPR model, injection pressure (p₁), andinjection rate (q₁). The downstream pressure value of the obstruction(p₃) is calculated using p₂, an estimated injectivity index II, and thereservoir pressure.

FIG. 3 is an illustration of another exemplary embodiment of a method ofthe invention. In this embodiment, two or more sets of injection data301 are collected and screened, preferably at the same reservoirpressure. A first formation injectivity index 302 is assumed. Using thefirst data set, the pressure drop across the obstruction for each datapoint (p_(j),q_(j)) is calculated 303.

The upstream pressure value of the obstruction, p₂, is calculated 304using a first OPR, injection pressure (p₁), and injection rate (q₁). Thedownstream pressure value of the obstruction (p₃) is calculated 305using p₂, a first estimated injectivity index, and the reservoirpressure (p_(R)). The pressure drop across the obstruction 306 is thepressure difference between the upstream and downstream pressure values(p₂-p₃). The square root of a term—pressure drop/water density—iscalculated 307 and plotted against different flow rate values obtainedfrom the above injection data set. Since the mechanical obstruction willapproximately behave like a downhole choke, it should follow the belowequation:

$q = {\frac{22800\mspace{14mu} D_{2}^{2}}{\sqrt{1 - \left( \frac{D_{2}}{D_{1}} \right)^{4}}}\sqrt{\frac{\Delta \; p}{\rho_{w}}}}$

Where,

-   -   q=injection rate, bbl/day    -   D₁=Tubular/openhole diameter, inch    -   D₂=Obstruction/equivalent choke diameter, inch    -   Δp=Pressure drop across the obstruction/equivalent choke, psi    -   ρ_(w)=water density, lbm/ft³

The obtained obstruction model is incorporated 308 with the OPR portionof the well performance model. Using another injection data set at,preferably, the same reservoir pressure, a second injectivity index isestimated by matching the rate value obtained from the new wellperformance model, with obstruction effect included, with the actualrate recorded by the solar flowmeter (SFM). Steps 302-308 are repeated309 till the first injectivity index and the second injectivity indexvalues converge with less than 5% tolerance. The equivalent chokediameter is then calculated 310 from the slope of the best fit lineusing the following equation:

$D_{2} = \left\lbrack \frac{m^{2}}{\left( {{5.198 \times 10^{8}} + \frac{m^{2}}{D_{1}^{4}}} \right)} \right\rbrack^{1/4}$

Where,

-   -   D₁=Tubular/openhole diameter, inch    -   D₂=Obstruction/equivalent choke diameter, inch    -   m=Slope of the obstruction choke model obtained from the        simulated obstruction model

Modeling of horizontal power water injectors using the IPR/OPR analysisshows remarkable results in terms of accuracy and reliability. The Joshicorrelation demonstrates excellent injection rate matching when comparedwith real Solar Flow Meter data. The assumption of constant injectivityindex to predict the reservoir pressure is valid in the short term wherethe change in injectivity index is minimal. This modeling approach witha simulated obstruction was tested to model mechanical wellboreobstructions.

Example

The following example further illustrates the compositions and methods.A well performance modeling approach was used to investigate and explainthe possible causes of an extraordinary gain in the injection ratenoticed after performing a well treatment plan, an acid stimulationtreatment. The well was confirmed having an obstruction in the openholesection prior to the acid stimulation which indicated the presence ofmechanical skin along with formation damage skin targeted by the matrixstimulation. The mechanical skin effect was modeled and incorporated inthe out flow performance to be compared with the formation damage skineffect. The improvement in the well conditions was dominated by themechanical skin (obstruction removal) rather than the formation skinimprovement. It was concluded that an acid wash or any other means ofremoving the mechanical skin arising from the obstruction accumulationin the openhole should have been sufficient as far as economics areconcerned.

A horizontal power water injection well, Well A, was drilled andcompleted in 2003. The initial injection rate was around 64 MBWD at 1300psi injection pressure. In late 2009, an obstruction was detected, usingcalipers, during a normal production logging job 9 feet below the linershoe. In 2012, an acid stimulation job was planned for this well.According to the last fall-off test conducted in 2008, the injectivityindex and skin were found to be 59.40 bbl/day/psi and +2.2 respectively.The acid job was successfully performed using bullheading technique andthe rate gain was more than 34 MBWD, from 21 to 55 MBWD, which is deemedremarkable compared to other wells in the area. The gain observed isbelieved to be due to the implementation of the bullheading techniquewith the horizontal open-hole power water injection well. However,obstruction removal from the wellbore was not taken into account to be acritical factor resulting in such high gain. The injection history ofthe well was reviewed and it shows indications of obstructiondevelopment in the wellbore such as a sudden increase in the wellheadsurface pressure at the same injection rate (see FIGS. 4 a-c). FIG. 4 ashows the injection rate and injection pressure history of Well A in2004 showing the potential obstruction development period. The averageinjection pressure was initially about 1300 psi and then increased toabout 1600 psi. The average fluid flow rate was 67MBWD.

FIG. 4 b shows the injection rate and injection pressure history of WellA in 2008. The average injection pressure was about 2300 psi and theaverage fluid flow rate was 57MBD. A fall-off test was conducted in late2008, and injectivity index was determined to be 59.40 bbl/day/psi. Thiscalculated injectivity index was used in the model. FIG. 4 c shows theinjection rate and injection pressure history of Well A in 2012following an acid wash treatment plan. Qavg is the average flow rateobserved at a pressure of Pinj. The 55 MBD was obtained by performing apost-stimulation injectivity test to quantify the gain after theacidizing job.

Calibration of the well performance models was done by comparing theiroutputs with the injection history at different reservoir pressures.Well test data available combined with rate tests were utilized tocalibrate Joshi model and estimate both permeability and K_(h)/K_(v)ratio of the reservoir. History matching was done at two different yearsusing exactly the same model taking in consideration the changes inreservoir pressure and assuming time-independent injectivity index.Results are shown in FIGS. 5 a and 5 b. The model shows good match withthe raw injection data recorded by the solar flowmeters. The model hereis the one without the effect of downhole obstruction. The matched rawdata were collected before the observation of obstruction in place. FIG.5 a shows the actual measurements of fluid flow rates from Well A in2009 and data points from both the Joshi model and the injectivity indexmodel. FIG. 5 b shows the actual measurements of fluid flow rates fromWell A in 2012 and data points from both the Joshi model and theinjectivity index model.

After constructing a reliable and calibrated model that takes intoconsideration both obstruction removal and/or formation damageimprovement, different scenarios were run by the model and compared withthe actual results to predict the type of skin effect being improved. Abase case was established first with injection pressure equal to 1500psi, reservoir pressure equal to 3831 psi and an injectivity index of59.40 bbl/Day/psi. The resulting flow rate, matching with the actualdata, was 21 MBWD showing the pre-acid stimulation well performance.Three scenarios were tried using the model to compare their outputs withthe actual gain resulted from the acid stimulation to predict whichscenario was most likely happened (see Table 1). The results show thatthe gain in flow rate is a product of both obstruction removal anddamaged skin improvement with the former being the dominant factor. Theactual gain was 34 MBWD, and it corresponds to the modeling scenariothat accounts for the obstruction removal with major skin improvement.Hence, an acid wash treatment with a high rate and pumping pressureshould have been enough to improve the well conditions. FIG. 6 shows asimulated obstruction model showing a linear relationship between thesquare root of pressure drop over density and the flow rate in BBL/Day.The obstruction diameter calculated using the well performance modelwith the simulated obstruction, and derived from the choke equation,using the slope of the straight line (m=10756) in FIG. 6 is 0.68″(equivalent to approximately 44/64 on the choke scale).

TABLE 1 Gain in Injec- Injectivity In- Scenario tion Rate MBWD dexbbl/day/psi Skin Obstruction removal with 22 200 −1.8 minor skinimprovement Obstruction removal with 33 500 −2.8 major skin improvementMajor skin improvement with 6 700 −3 obstruction still in place

Moreover, the foregoing has broadly outlined certain objectives,features, and technical advantages of the present invention and adetailed description of the invention so that embodiments of theinvention may be better understood in light of features and advantagesof the invention as described herein, which form the subject of certainclaims of the invention. It should be appreciated that the conceptionand specific embodiment disclosed may be readily utilized as a basis formodifying or designing other structures for carrying out the samepurposes of the present invention. It should also be realized that suchequivalent constructions do not depart from the invention as set forthin the appended claims. The novel features which are believed to becharacteristic of the invention, both as to its organization and methodof operation, together with further objects and advantages is betterunderstood from the following description when considered in connectionwith the accompanying figures. It is to be expressly understood,however, that such description and figures are provided for the purposeof illustration and description only and are not intended as adefinition of the limits of the present invention. It will be apparentto those skilled in the art that various modifications and changes canbe made within the spirit and scope of the invention as described in theforegoing specification.

That claimed is:
 1. A method to estimate one or more physical dimensionsof one or more actual obstructions identified as being in a wellbore ofan injection well, the method comprising: (a) estimating one or morelocations within the wellbore and one or more physical dimensions of oneor more actual obstructions to thereby define a simulated obstructionwithin the wellbore; (b) obtaining two or more sets of actualmeasurements of two or more characteristics of fluid flow in thewellbore including two or more actual injection rates and two or moreactual injection pressures; (c) calculating a plurality of actualupstream pressure values of the simulated obstruction, the upstreampressure values being responsive to a first outflow performancerelationship and a first set of actual measurements of two or morecharacteristics of fluid flow in the wellbore, the first set ofmeasurements including a first set of actual fluid injection rates and afirst set of actual injection pressures; (d) calculating a plurality ofcorresponding downstream pressure values across the simulatedobstruction, the corresponding downstream pressure values beingresponsive to a first estimated injectivity index value, one or moreactual measurements of one or more characteristics of the reservoirassociated with the injection well, and the first set of actualmeasurements of two or more characteristics of fluid flow in thewellbore; (e) determining one or more functions to associate a pluralityof pressure differentials between the upstream pressure values and thecorresponding downstream pressure values with the first set of actualfluid injection rates responsive to a function of estimated downholechoke behavior for the wellbore to thereby model the fluid flow acrossthe simulated obstruction to thereby define the simulated obstructionmodel; (f) determining a second outflow performance relationship for thefluid flow through the wellbore responsive to the simulated obstructionmodel to thereby model well performance with the simulated obstruction;(g) determining a second estimated injectivity index value responsive tomatching a second set of actual measurements of two or morecharacteristics of fluid flow in the wellbore with a set of simulatedfluid flow values obtained from the well performance model with thesimulated obstruction, the second set of actual measurements including asecond set of actual fluid injection rates and a second set of actualinjection pressures; (h) performing iteratively steps (b) to (g) untilthe first estimated injectivity index value and the second estimatedinjectivity index value converge within preselected tolerance limits;and (i) determining one or more physical dimensions of one or moreactual obstructions in the wellbore responsive to the simulatedobstruction model and a plurality of measurements of one or morecharacteristics associated with the wellbore when the first estimatedinjectivity index value and the second estimated injectivity index valueconverge within preselected tolerance limits.
 2. A method as defined inclaim 1, wherein the two or more sets of measurements of two or morecharacteristics of fluid flow in the wellbore including two or moreinjection rates and two or more injection pressures are obtained atsubstantially similar values of reservoir pressure associated with theinjection well.
 3. A method as defined in claim 2, wherein the two ormore sets of measurements of two or more characteristics of fluid flowin the wellbore are obtained using a solar flowmeter.
 4. A method asdefined in claim 1, wherein the plurality of measurements of one or morecharacteristics associated with the wellbore includes one or morephysical dimensions of the wellbore.
 5. A method as defined in claim 4,wherein the one or more physical dimensions of the wellbore includes adiameter of the wellbore.
 6. A method as defined in claim 1, wherein theinjection well is a power water injection well.
 7. A system to estimateone or more physical dimensions of one or more actual obstructionsidentified as being in a wellbore of an injection well, the systemcomprising: one or more processors; one or more input and output unitsin communication with the one or more processors and positioned toreceive a user selection of a wellbore of an injection well; one or moredatabases in communication with the one or more processors, the one ormore databases including a plurality of actual measurements of one ormore characteristics of fluid flow in the wellbore of an injection well,a plurality of actual measurements of one or more characteristics of areservoir associated to the injection well, and a plurality of actualmeasurements of one or more characteristics of the wellbore of theinjection well; non-transitory computer-readable medium positioned incommunication with the one or more processors and having computerprogram stored thereon including a set of instructions that whenexecuted by one or more processors cause the one or more processors toperform operations of: (a) estimating one or more locations within thewellbore and one or more physical dimensions of one or more actualobstructions to thereby define a simulated obstruction within thewellbore; (b) obtaining two or more sets of actual measurements of twoor more characteristics of fluid flow in the wellbore including two ormore actual injection rates and two or more actual injection pressures;(c) calculating a plurality of actual upstream pressure values of thesimulated obstruction, the upstream pressure values being responsive toa first outflow performance relationship and a first set of actualmeasurements of two or more characteristics of fluid flow in thewellbore, the first set of measurements including a first set of actualfluid injection rates and a first set of actual injection pressures; (d)calculating a plurality of corresponding downstream pressure valuesacross the simulated obstruction, the corresponding downstream pressurevalues being responsive to a first estimated injectivity index value,one or more actual measurements of one or more characteristics of thereservoir associated with the injection well, and the first set ofactual measurements of two or more characteristics of fluid flow in thewellbore; (e) determining one or more functions to associate a pluralityof pressure differentials between the upstream pressure values and thecorresponding downstream pressure values with the first set of actualfluid injection rates responsive to a function of estimated downholechoke behavior for the wellbore to thereby model the fluid flow acrossthe simulated obstruction to thereby define the simulated obstructionmodel; (f) determining a second outflow performance relationship for thefluid flow through the wellbore responsive to the simulated obstructionmodel to thereby model well performance with the simulated obstruction;(g) determining a second estimated injectivity index value responsive tomatching a second set of actual measurements of two or morecharacteristics of fluid flow in the wellbore with a set of simulatedfluid flow values obtained from the well performance model with thesimulated obstruction, the second set of actual measurements including asecond set of actual fluid injection rates and a second set of actualinjection pressures; (h) performing iteratively steps (b) to (g) untilthe first estimated injectivity index value and the second estimatedinjectivity index value converge within preselected tolerance limits;and (i) determining one or more physical dimensions of one or moreactual obstructions in the wellbore responsive to the simulatedobstruction model and a plurality of measurements of one or morecharacteristics associated with the wellbore when the first estimatedinjectivity index value and the second estimated injectivity index valueconverge within preselected tolerance limits.
 8. A system as defined inclaim 7, wherein the two or more sets of measurements of two or morecharacteristics of fluid flow in the wellbore including two or moreinjection rates and two or more injection pressures are obtained atsubstantially similar values of reservoir pressure associated with theinjection well.
 9. A system as defined in claim 7, wherein the pluralityof measurements of one or more characteristics associated with thewellbore includes one or more physical dimensions of the wellbore.
 10. Asystem as defined in claim 9, wherein the one or more physicaldimensions of the wellbore includes a diameter of the wellbore.
 11. Asystem as defined in claim 7, wherein the injection well is a powerwater injection well.
 12. A computer-implemented method to determinedimensions of one or more actual obstructions identified as being in awellbore of an injection well, the method comprising: (a) obtaining aplurality of measurements of one or more characteristics of fluid flowin a wellbore of an injection well, a plurality of measurements of oneor more characteristics of a reservoir associated with the injectionwell, and a plurality of measurements of one or more characteristicsassociated with the wellbore of the injection well; (b) creating one ormore correlations based on a first estimated injectivity index tosimulate fluid flow across one or more simulated mechanical obstructionsto thereby define a simulated obstruction performance model, the one ormore correlations being responsive to the plurality of measurements ofone or more characteristics of fluid flow in the wellbore of theinjection well, the plurality of measurements of one or morecharacteristics of the reservoir associated with the injection well, theplurality of measurements of one or more characteristics associated withthe wellbore of the injection well, and a plurality of simulated fluidflow measurements across the at least one simulated mechanicalobstruction in the wellbore; (c) determining a second estimatedinjectivity index, responsive to the simulated obstruction performancemodel, the plurality of measurements of one or more characteristics ofactual fluid flow in the wellbore of the injection well, the pluralityof measurements of one or more characteristics of the reservoirassociated with the injection well, and the plurality of measurements ofone or more characteristics associated with the wellbore of theinjection well; (d) performing iteratively steps (a) to (c) until thefirst estimated injectivity index value and the second estimatedinjectivity index value converge within preselected tolerance limits;and (e) determining dimensions of the one or more actual obstruction inthe wellbore responsive to the simulated obstruction performance modeland the plurality of measurements of one or more characteristicsassociated with the wellbore of the injection well when the firstestimated injectivity index and the second estimated injectivity indexconverge within acceptable tolerance limits.
 13. A method as defined inclaim 12, wherein the simulated obstruction performance model includesat least one of the following: an outflow performance relationshipanalysis and an inflow performance relationship analysis.
 14. A methodas defined in claim 13, wherein the outflow performance relationshipanalysis is responsive to the plurality of measurements of one or morecharacteristics of fluid flow in the wellbore of the injection well. 15.A method as defined in claim 13, wherein the inflow performancerelationship analysis is responsive to the plurality of measurements ofone or more characteristics of fluid flow in the wellbore of theinjection well and the plurality of measurements of one or morecharacteristics of the reservoir associated with the injection well. 16.A method as defined in claim 12, wherein the one or more characteristicsof fluid flow in the wellbore includes one of the following: injectionrate and injection pressure.
 17. A method as defined in claim 12,wherein the plurality of measurements of the one or more characteristicsof fluid flow in the wellbore are obtained using a solar flowmeter. 18.A method as defined in claim 12, wherein the plurality of measurementsof one or more characteristics associated with the wellbore includes oneor more physical dimensions of the wellbore.
 19. A method as defined inclaim 12, wherein the one or more physical dimensions of the wellboreincludes a diameter of the wellbore.
 20. A method as defined in claim12, wherein the injection well is a power water injection well.